An electric power system comprises a power transmission and/or distribution network interconnecting geographically separated regions, and a plurality of substations at the nodes of the power network. The substations include equipment for transforming voltages and for switching connections between individual lines of the power network. Power generation and load flow to consumers is managed by a central Energy Management System (EMS) and/or supervised by a Supervisory Control And Data Acquisition (SCADA) system located at a Network Control Centre (NCC).
Substations in high and medium voltage power networks include primary devices such as electrical cables, lines, bus bars, switches such as breakers or disconnectors, power transformers and instrument transformers, which are generally arranged in switch yards and/or bays. These primary devices are operated in an automated way via a Substation Automation (SA) system responsible for protecting, controlling, measuring and monitoring of substations. The SA system comprises secondary devices, so-called digital relays, which are interconnected in an SA communication network, and which interact with the primary devices via a process interface. These devices are generally assigned to one of three hierarchical levels, which are (a) the station level including an Operator Work Station (OWS) with a Human-Machine Interface (HMI) as well as the gateway to the Network Control Centre (NCC), (b) the bay level with its devices for protection, control and measurement, and (c) the process level comprising e.g. electronic sensors for voltage, current and gas density measurements as well as contact probes for sensing switch and transformer tap changer positions, as well as actuators controlling the drive of a switch or tap changer. At the process level, intelligent actuators may be integrated in the respective primary devices and connected to a bay unit via a serial link or an optical process bus. The bay units are connected to each other and to the devices on the station level via an inter-bay or station bus.
Today's SA systems desire interoperability between all substation devices independently of their manufacturer. To that effect, an internationally accepted standard for communication between the secondary devices of a substation has been introduced by the International Electrotechnical Committee under the name of IEC 61850 “communication networks and systems in substations”. All EEC 61850 compliant devices connected to the SA network are called Intelligent Electronic Devices (IED).
IEC 61850 defines an abstract object model for compliant substations, and a method how to access these objects over a network. This allows the substation-specific applications such as the OWS to operate with standard objects, while the actual objects in the substation may be realized differently by the IEDs of different manufacturers. The abstract object model according to the above standard represents the SA functionality in terms of logical nodes within logical devices that are allocated to the IEDs as the physical devices.
IEC 61850 communication protocols for non-time critical messages are client-server based, which enables several clients to access data from a server, define the semantics of the data within the substation in a standardized object-oriented way, and offer a standardized method to transfer data between different engineering tools in a standardized format. The communication between IEDs is handled, for non-time critical messages, via a Manufacturing Message Specification (MMS) communication stack built on OSI/TCP/IP/Ethernet, or for time critical messages, via so-called Generic Object Oriented Substation Events (GOOSE) that build directly on the Ethernet link layer of the communication stack. Very time-critical signals at the process level such as trip commands and analogue voltages or currents use a simplified variant of GOOSE known as SV (Sampled Values) that also builds directly on the Ethernet link layer.
One consequence of interoperability mentioned above is that IEDs from different suppliers may be combined into one SA system. Since the IEDs are initially configured during an engineering phase, the corresponding dedicated engineering or SA configuration tools of the different suppliers exchange information about the IEDs. To this effect, the complete SA system with all its primary devices, IEDs and communication links should be specified in a computer-readable manner. This is enabled by the comprehensive XML-based Substation Configuration description Language (SCL) that is part of the IEC 61850 standard. In short, the IEC 61850 SCL language provides for a standardized description of the primary devices, the secondary devices with their Protection, Control and Monitoring (PCM) functions, the logical structure of the communication system, and the relation between the IEDs and the primary devices. Therefore, IEC 61850 SCL enables an automated configuration of the IEDs.
The SCL language is used to describe the capabilities of a particular IED or IED type in an IED Capability Description (ICD) file that lists the application functions of a physical device, e.g. its implemented protection functionality. A Configured IED Description (CID) includes further the communication properties of the IED, e.g. its unique IP address. A Substation Configuration Description (SCD) file in the SCL language describes the primary objects, the functions implemented in each IED in terms of logical nodes, and the communication connections of a particular substation. Therefore, the SCD file comprises (1) a switch yard naming and topology description, (2) an IED configuration description, (3) the relationship between switch yard elements and IED functions, and (4) a description of a communication network. Accordingly, if a particular IED is used within an SA system, an object instance of the IED type is inserted into the corresponding SCD file. The SCL language then enables specifying typical or individual values for the data attributes carried by the data instance, related to the particular IED, e.g. values of the configuration attributes and setting parameters. The connection between the power process and the SA system is described in the SCL language by allocating or attaching logical nodes to elements of the primary equipment. A switch control logical node can be attached to a switching device, whereas a measurement logical node is allocated to an instrument transformer. The semantic meaning of a function within an SA system is determined by the logical node type or class, in combination with the switch yard and/or bay to which it is allocated.
A file in the IEC61850-conformant description language SCL, including the above mentioned SCD or ICD files relating to the configuration of the station and the automation devices, describes an instance of the SCL object model in a serialized form and with a standardized syntax. Its syntax definition is described in IEC 61850, Part 6, as an XML schema and as such encoded in computer readable form. Established software tools allow validating an SCL file against Part 6 of IEC 61850 through XML schema validation at syntax level.
On the other hand, the semantics or content of an SCL file is independent from the syntax and can only be fully understood by reference to the SCL object model itself. In other words, successful validation of the SCL file in terms of adherence to the SCL schema does not necessarily imply that the SCL file is valid or conformant in the sense of substation automation (conformity to plaintext parts of the standard IEC 61850) as well as power system operation or user specification (conformity to project/application). In other words, there is no automated detection of inconsistencies in SCL files related to the following extended constraints:    1. IEC 61850 defined notations other than those in the SCL-schema of Part 6, especially the conceptual data model defined in Parts 7-2, 7-3, 7-4 and 8-1 of the standard.    2. Application specific, project specific or other user defined requirements.    3. General power system conventions.